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UPDATE OF CRITERIA AIR CONTAMINANT EMISSIONS IN GHGENIUS

Prepared For:

Natural Resources Canada Office of Energy Efficiency

580 Booth Street Ottawa, Ontario

K1A 0E4

Prepared By

(S&T)2 Consultants Inc. 11657 Summit Crescent

Delta, BC Canada, V4E 2Z2

Date: March 11, 2008

(S&T)2 UPDATE OF CRITERIA AIR CONTAMINANT

EMISSIONS IN GHGENIUS i

EXECUTIVE SUMMARY The GHGenius model has been developed for Natural Resources Canada over the past eight years. It is based on the 1998 version of Dr. Mark Delucchi’s Lifecycle Emissions Model (LEM). GHGenius is capable of analyzing the energy balance and emissions of many contaminants associated with the production and use of traditional and alternative transportation fuels.

GHGenius is capable of estimating life cycle emissions of the primary greenhouse gases and the criteria pollutants from combustion sources. The specific gases that are included in the model include:

• Carbon dioxide (CO2), • Methane (CH4), • Nitrous oxide (N2O), • Chlorofluorocarbons (CFC-12), • Hydro fluorocarbons (HFC-134a), • The CO2-equivalent of all of the contaminants above. • Carbon monoxide (CO), • Nitrogen oxides (NOx), • Non-methane organic compounds (NMOCs), weighted by their ozone forming

potential, • Sulphur dioxide (SO2), • Total particulate matter.

The model is capable of analyzing the emissions from conventional and alternative fuelled internal combustion engines or fuel cells for light duty vehicles, for class 3-7 medium-duty trucks, for class 8 heavy-duty trucks, for urban buses and for a combination of buses and trucks, and for light duty battery powered electric vehicles. There are over 200 vehicle and fuel combinations possible with the model.

This work primarily considered the emissions of the criteria air contaminants (CAC) calculated by the model. The emission factors used to calculate these emissions have been reviewed and updated where possible. The US AP-42 documents were the source of many of the emission factors. In some cases this involved revised estimates for methane and nitrous oxides from some combustion sources and thus the GHG emissions calculated by this version of the model have changed as well.

For the well established processes in the model, such as electric power production and oil refining, it has been possible to further regionalize the CAC emissions with different values for each region of Canada and for the United States.

There is now more consistency in how the CAC emissions are treated in the model. All of the processes where CAC’s are calculated now have a base value and the ability to change that value over time as new control strategies are implemented.

A significant amount of work was undertaken with the US EPA model NONROAD2005 to estimate the emissions from off road and stationary internal combustion engines. The N2O emission rate for all of these sources was also updated with the latest IPCC emission estimates.

There remain a number of fuel pathway technologies in GHGenius that are still under development or have not been reviewed and included in AP-42. For these systems other,


EMISSIONS IN GHGENIUS ii

probably less reliable, estimates have been identified in the literature and incorporated into the model. The estimates that have been made in these cases are considered to be conservative. Some effort has been made to have some consistency in the choice of emissions factors between similar processes.

A large number of small changes have been made to the emission factors in the model. These changes have also included further regionalization of some pathways and further differentiation of the Canadian emissions compared to the US emissions. While the focus of the work has been on the CAC emissions in a number of cases changes to methane and nitrous oxide emission factors have also been made. In addition there were some structural changes to how future emissions reductions are included in the model and the structure of how the biodiesel process emissions are calculated.

All of these changes have resulted in small changes in the projected GHG performance of the fuels included in the model. In the following table the upstream emissions for a selection of fuels is shown and compared to the results from version 3.11.

Table ES- 1 Comparison of Upstream GHG Emissions GHGenius 3.11 vs. 3.12

GHGenius 3.11 GHGenius 3.12 g CO2 eq/GJ g CO2 eq/GJLow Sulphur Gasoline 22,607 22,426On Road Diesel 18,732 18,586Corn Ethanol 37,169 37,355Wheat Ethanol 38,055 38,330Canola Biodiesel 17,352 17,737Soy Biodiesel 23,817 24,222Tallow Biodiesel -6,508 -6,624SMR Hydrogen 108,793 108,899Electrolytic Hydrogen 127,807 127,950CNG 10,007 10,076LPG 12,373 12,207FT Natural Gas 31,449 31,300FT Coal 110,112 109,711Methanol (Natural Gas) 20,019 19,795


EMISSIONS IN GHGENIUS iii

TABLE OF CONTENTS

EXECUTIVE SUMMARY ............................................................................................................ I

TABLE OF CONTENTS ............................................................................................................ III

LIST OF TABLES.......................................................................................................................V

LIST OF FIGURES....................................................................................................................VI

1. INTRODUCTION ................................................................................................................. 1 1.1 SCOPE OF WORK.......................................................................................................... 2

2. ELECTRIC POWER EMISSIONS........................................................................................ 4 2.1 UNCONTROLLED EMISSION FACTORS............................................................................. 4 2.2 TECHNOLOGY CONTROL FACTORS ................................................................................ 5 2.3 COUNTRY CONTROL FACTORS ...................................................................................... 6

3. OIL REFINING EMISSIONS ................................................................................................ 8

4. OFF ROAD MOBILE EQUIPMENT.................................................................................... 11 4.1 TRAINS....................................................................................................................... 11 4.2 MARINE VESSELS ....................................................................................................... 14 4.3 VEHICLES................................................................................................................... 15

4.3.1 Scrapers............................................................................................................. 16 4.3.2 Wheeled Loaders............................................................................................... 19 4.3.3 Off Road Trucks................................................................................................. 21 4.3.4 Farm Tractors .................................................................................................... 23

4.3.4.1 Diesel .............................................................................................................. 24 4.3.4.2 Gasoline.......................................................................................................... 26

4.4 STATIONARY ENGINES ................................................................................................ 28 4.4.1 Gasoline............................................................................................................. 28 4.4.2 Diesel Fuel ......................................................................................................... 30

5. COMBUSTION EMISSIONS.............................................................................................. 33 5.1 INDUSTRIAL BOILERS .................................................................................................. 33

5.1.1 Solid Fuels ......................................................................................................... 33 5.1.2 Gaseous Fuels................................................................................................... 34 5.1.3 Liquid Fuels........................................................................................................ 35

5.2 BUILDING HEATERS..................................................................................................... 36 5.2.1 Gaseous Fuels................................................................................................... 36 5.2.2 Liquid Fuels........................................................................................................ 37

5.3 COMPRESSORS .......................................................................................................... 38 6. PROCESS EMISSIONS .................................................................................................... 40

6.1 PETROLEUM REFINERIES............................................................................................. 40 6.2 ETHANOL PRODUCTION............................................................................................... 41 6.3 BUTANOL ................................................................................................................... 42 6.4 HYDROGEN PLANTS.................................................................................................... 42 6.5 METHANOL PRODUCTION ............................................................................................ 44


EMISSIONS IN GHGENIUS iv

6.6 SYNTHETIC GAS PRODUCTION..................................................................................... 44 6.7 FT DISTILLATE PLANTS ............................................................................................... 45 6.8 MIXED ALCOHOLS FACILITIES ...................................................................................... 46 6.9 BIODIESEL PLANTS ..................................................................................................... 46

6.9.1 Transesterification.............................................................................................. 47 6.9.2 Oil Extraction...................................................................................................... 47

6.9.2.1 Canola............................................................................................................. 47 6.9.2.2 Soybeans ........................................................................................................ 48 6.9.2.3 Palm................................................................................................................ 48 6.9.2.4 Tallow.............................................................................................................. 48 6.9.2.5 Yellow Grease................................................................................................. 48 6.9.2.6 Fish Oil............................................................................................................ 49

6.10 DIMETHYL ETHER PRODUCTION................................................................................... 49 7. RESULTS .......................................................................................................................... 50

8. REFERENCES .................................................................................................................. 51


EMISSIONS IN GHGENIUS v

LIST OF TABLES TABLE 2-1 UNCONTROLLED EMISSION FACTORS ...................................................................... 4 TABLE 2-2 CANADIAN NOX AND SOX COAL EMISSION RATES ................................................... 6 TABLE 2-3 CANADIAN ADJUSTMENT FACTORS.......................................................................... 7 TABLE 2-4 IMPACT OF CHANGES ON AVERAGE CANADIAN ELECTRICITY MIX .............................. 7 TABLE 3-1 US REFINERY EMISSIONS – 1999........................................................................... 8 TABLE 3-2 US REFINERY EMISSIONS BY GHGENIUS REGION ................................................... 9 TABLE 3-3 US REFINERY REGIONAL EMISSION ADJUSTMENT FACTORS .................................... 9 TABLE 3-4 CANADIAN VS. US REFINERY EMISSIONS – 2001..................................................... 9 TABLE 3-5 CANADIAN REFINERY REGIONAL EMISSION ADJUSTMENT FACTORS ........................ 10 TABLE 3-6 COMPARISON OF RESULTS GHGENIUS 3.11 AND 3.12........................................... 10 TABLE 4-1 EPA LINE HAUL LOCOMOTIVE EMISSIONS ............................................................. 11 TABLE 4-2 RAILWAY EMISSION FACTORS- FREIGHT TRAINS.................................................... 12 TABLE 4-3 COMPARISON OF LOCOMOTIVE EMISSIONS ............................................................ 12 TABLE 4-4 SULPHUR IN FUEL SCHEDULE ............................................................................... 13 TABLE 4-5 COMPARISON OF EMISSIONS FOR TRAINS 2007 ..................................................... 14 TABLE 4-6 MARINE VESSEL EMISSION FACTORS .................................................................... 14 TABLE 4-7 COMPARISON OF EMISSIONS FOR TANKERS 2007 .................................................. 15 TABLE 4-8 UNCONTROLLED SCRAPER EMISSIONS.................................................................. 17 TABLE 4-9 PARAMETERS FOR MODELLING EMISSION REDUCTIONS ......................................... 18 TABLE 4-10 COMPARISON OF EMISSIONS FOR SCRAPERS 2007................................................ 18 TABLE 4-11 COMPARISON OF EMISSIONS FOR WHEELED LOADERS 2007 .................................. 21 TABLE 4-12 COMPARISON OF EMISSIONS FOR OFF ROAD TRUCKS 2007 ................................... 23 TABLE 4-13 COMPARISON OF EMISSIONS FOR DIESEL TRACTORS 2007 .................................... 26 TABLE 4-14 COMPARISON OF EMISSIONS FOR GASOLINE TRACTORS 2007................................ 28 TABLE 4-15 COMPARISON OF EMISSIONS FOR GASOLINE STATIONARY ENGINES 2007............... 30 TABLE 4-16 COMPARISON OF EMISSIONS FOR STATIONARY DIESEL ENGINES 2007 ................... 32 TABLE 5-1 COMPARISON OF EMISSIONS FOR SOLID FUEL INDUSTRIAL BOILERS 2007 .............. 34 TABLE 5-2 COMPARISON OF EMISSIONS FOR GASEOUS FUEL INDUSTRIAL BOILERS 2007......... 35 TABLE 5-3 COMPARISON OF EMISSIONS FOR LIQUID FUEL INDUSTRIAL BOILERS 2007 ............. 36 TABLE 5-4 COMPARISON OF EMISSIONS FOR NATURAL GAS BUILDING HEATERS 2007............. 37 TABLE 5-5 COMPARISON OF EMISSIONS FOR LIQUID FUEL BUILDING HEATERS 2007................ 38 TABLE 5-6 COMPARISON OF EMISSIONS FOR COMPRESSORS 2007......................................... 39 TABLE 6-1 COMPARISON OF PROCESS EMISSIONS FOR GASOLINE AND DIESEL 2007............... 40


EMISSIONS IN GHGENIUS vi

TABLE 6-2 ETHANOL PROCESS EMISSION FACTORS............................................................... 41 TABLE 6-3 COMPARISON OF RESULTS GHGENIUS 3.11 AND 3.12 CORN ETHANOL.................. 42 TABLE 6-4 NATURAL GAS REFORMER EMISSION FACTORS ..................................................... 43 TABLE 6-5 LINDE SMR EMISSION RATES............................................................................... 43 TABLE 6-6 EMISSION FACTORS ASSUMPTIONS....................................................................... 44 TABLE 6-7 COAL TO FTD PROCESS EMISSIONS ESTIMATES ................................................... 45 TABLE 6-8 PROCESS EMISSIONS COMPARISON...................................................................... 46 TABLE 6-9 COMPARISON OF RESULTS GHGENIUS 3.11 AND 3.12 CANOLA BIODIESEL............. 48 TABLE 7-1 COMPARISON OF UPSTREAM GHG EMISSIONS GHGENIUS 3.11 VS. 3.12............... 50

LIST OF FIGURES FIGURE 2-1 NOX AND SOX CONTROL FACTORS ........................................................................ 5 FIGURE 4-1 SCRAPER EMISSIONS – NOX AND CO................................................................... 16 FIGURE 4-2 SCRAPER EMISSIONS – PM AND HC..................................................................... 17 FIGURE 4-3 NOX AND CO EMISSIONS WHEELED LOADERS ...................................................... 19 FIGURE 4-4 HC AND PM EMISSIONS WHEELED LOADERS ........................................................ 20 FIGURE 4-5 NOX AND CO EMISSIONS OFF ROAD TRUCKS ....................................................... 22 FIGURE 4-6 HC AND PM EMISSIONS OFF ROAD TRUCKS ......................................................... 22 FIGURE 4-7 NOX AND CO EMISSIONS DIESEL FARM TRACTORS............................................... 24 FIGURE 4-8 HC AND PM EMISSIONS DIESEL FARM TRACTORS................................................. 25 FIGURE 4-9 NOX, HC EXHAUST AND CO EMISSIONS GASOLINE FARM TRACTORS .................... 27 FIGURE 4-10 HC EVAPORATIVE AND PM EMISSIONS GASOLINE FARM TRACTORS .................... 27 FIGURE 4-11 HC AND CO EMISSIONS GASOLINE ENGINES ...................................................... 29 FIGURE 4-12 NOX AND PM EMISSIONS GASOLINE ENGINES .................................................... 29 FIGURE 4-13 NOX AND CO EMISSIONS DIESEL ENGINES......................................................... 31 FIGURE 4-14 HC AND PM EMISSIONS DIESEL ENGINES........................................................... 31


EMISSIONS IN GHGENIUS 1

1. INTRODUCTION The GHGenius model has been developed for Natural Resources Canada over the past eight years. It is based on the 1998 version of Dr. Mark Delucchi’s Lifecycle Emissions Model (LEM). GHGenius is capable of analyzing the energy balance and emissions of many contaminants associated with the production and use of traditional and alternative transportation fuels.

GHGenius is capable of estimating life cycle emissions of the primary greenhouse gases and the criteria pollutants from combustion sources. The specific gases that are included in the model include:

• Carbon dioxide (CO2), • Methane (CH4), • Nitrous oxide (N2O), • Chlorofluorocarbons (CFC-12), • Hydro fluorocarbons (HFC-134a), • The CO2-equivalent of all of the contaminants above. • Carbon monoxide (CO), • Nitrogen oxides (NOx), • Non-methane organic compounds (NMOCs), weighted by their ozone forming

potential, • Sulphur dioxide (SO2), • Total particulate matter.

The model is capable of analyzing the emissions from conventional and alternative fuelled internal combustion engines or fuel cells for light duty vehicles, for class 3-7 medium-duty trucks, for class 8 heavy-duty trucks, for urban buses and for a combination of buses and trucks, and for light duty battery powered electric vehicles. There are over 200 vehicle and fuel combinations possible with the model.

GHGenius can predict emissions for past, present and future years through to 2050 using historical data or correlations for changes in energy and process parameters with time that are stored in the model. The fuel cycle segments considered in the model are as follows:

• Vehicle Operation Emissions associated with the use of the fuel in the vehicle. Includes all greenhouse gases.

• Fuel Dispensing at the Retail Level Emissions associated with the transfer of the fuel at a service station from storage into the vehicles. Includes electricity for pumping, fugitive emissions and spills.

• Fuel Storage and Distribution at all Stages Emissions associated with storage and handling of fuel products at terminals, bulk plants and service stations. Includes storage emissions, electricity for pumping, space heating and lighting.

• Fuel Production (as in production from raw materials) Direct and indirect emissions associated with conversion of the feedstock into a saleable fuel product. Includes process emissions, combustion emissions for process heat/steam, electricity generation, fugitive emissions and emissions from the life cycle of chemicals used for fuel production cycles.

• Feedstock Transport



Direct and indirect emissions from transport of feedstock, including pumping, compression, leaks, fugitive emissions, and transportation from point of origin to the fuel refining plant. Import/export, transport distances and the modes of transport are considered.

• Feedstock Production and Recovery Direct and indirect emissions from recovery and processing of the raw feedstock, including fugitive emissions from storage, handling, upstream processing prior to transmission, and mining.

• Fertilizer Manufacture Direct and indirect life cycle emissions from fertilizers, and pesticides used for feedstock production, including raw material recovery, transport and manufacturing of chemicals. This is not included if there is no fertilizer associated with the fuel pathway.

• Land use changes and cultivation associated with biomass derived fuels Emissions associated with the change in the land use in cultivation of crops, including N2O from application of fertilizer, changes in soil carbon and biomass, methane emissions from soil and energy used for land cultivation.

• Carbon in Fuel from Air Carbon dioxide emissions credit arising from use of a renewable carbon source that obtains carbon from the air.

• Leaks and flaring of greenhouse gases associated with production of oil and gas Fugitive hydrocarbon emissions and flaring emissions associated with oil and gas production.

• Emissions displaced by co-products of alternative fuels Emissions displaced by co-products of various pathways. System expansion is used to determine displacement ratios for co-products from biomass pathways.

• Vehicle assembly and transport Emissions associated with the manufacture and transport of the vehicle to the point of sale, amortized over the life of the vehicle.

• Materials used in the vehicles Emissions from the manufacture of the materials used to manufacture the vehicle, amortized over the life of the vehicle. Includes lube oil production and losses from air conditioning systems.

1.1 SCOPE OF WORK

The emission factors for criteria air contaminants (CAC) emissions in GHGenius are mostly found on sheet N of the model and include the emission factors for off road engines, stationary combustion sources and process (non-energy) emissions. Many of the emission factors on this sheet have not been reviewed for some time and with constantly changing emission technologies and regulations it is appropriate to review these emission factors to ensure that they reflect the most up to date information possible.

The work also considers the indirect energy emissions that are found on row 24 on sheet N. This is the energy that is embedded in transportation systems (e.g. trains, vessels, farm equipment, etc.) that are used in the lifecycle of many of the fuels. Emission factors for CAC emissions are also found on sheet J for Electric Power and sheet G for Oil Refineries. These emissions have also been reviewed. We have not reviewed the emission factors in the model for the production of materials.

A number of sources of information have been considered for this work including:



• The latest US EPA NONROAD model for mobile emissions • EPA AP-42 emission factors for stationary combustion and process

emissions • Environment Canada emission factors for CAC’s, methane and N2O • Transport Canada emission factors • Industry Associations, such as the Railway Association of Canada and others

including associations representing marine transportation • Other work undertaken for NRCan and Environment Canada on fuel

production systems in recent years • And other sources as necessary to generate a complete data set.

As part of this work we have also reviewed the emission control factors that are applied in GHGenius to adjust these emissions over time. The same data sources have been reviewed for guidance on how best to adjust these emissions.

This work also includes this report on the data sources, the assumptions made, and the changes that have resulted in the model results. The version of the model that accompanies this report is GHGenius 3.12.



2. ELECTRIC POWER EMISSIONS The emissions from the production of electric power have been reviewed and adjusted where necessary. These emissions are found on sheet J of the model. This sheet is somewhat unique in the model as it has both raw data and results on the same sheet.

The calculations of emissions are based on the uncontrolled emissions for the technology from the US EPA AP-42 report series, multiplied by a control factor, and a country factor. The control factor is derived from US EIA Energy Outlook projections for NOx and SOx, for PM emissions the coal and fuel oil factors are estimated based on year, and for the other technologies and pollutants the user can input a technology control factor.

2.1 UNCONTROLLED EMISSION FACTORS

Few changes were required to the AP-42 uncontrolled emission factors for most fuels but there were significant changes required for the biomass pathway. In Delucchi’s Lifecycle Emissions Model (LEM) the biomass emissions were not derived from AP-42 but rather from an NREL assessment of the technology. For consistency we have used the AP-42 factors for biomass. The new uncontrolled emission factors are shown in the following table. The values that have changed are in italics. If the emissions increased then the result is in a bold italic.

Table 2-1 Uncontrolled Emission Factors

Coal Fuel oil NG boiler NG Turbine

Wind Other Carbon

Biomass Hydro

kg/tonne kg/kL kg/ML g/GJ g/GJ g/GJ g/GJ g/kWh Aldehydes 0.001 0.005 0.00 0.00 0.00 0.00 2.25 0.00 NMOC 0.03 0.09 0.14 1.03 0.00 2.18 7.75 1.52 Ozone-weighted NMOC calculated calculated calculated calculated calculated calculated calculated calculatedCH4 0.02 0.03 0.04 3.70 0.00 0.80 9.04 0.30 CO 0.25 0.60 1.35 35.29 0.00 14.37 258.20 2.00 N2O (g/GJ) 0.04 0.01 0.04 1.29 0.00 0.32 4.0 0.00 NOx as NO2 10.85 5.40 4.49 137.71 0.00 129.37 94.67 0.00 SOx 18.03 19.33 0.00 10.02 0.00 476.76 92.78 0.00 PM 42.62 1.51 0.12 2.84 0.00 36.30 172.13 0.00 PM10 9.61 1.07 0.12 2.84 0.00 25.72 154.92 0.00 PM2.5 2.51 0.78 0.12 2.84 0.00 18.75 133.40 0.00

In addition to the biomass changes, the Natural Gas Turbine values were all changed. It appeared that there was a unit conversion error between AP-42 and the original LEM values. These values are now lower than previous versions of the model. A few other values in the table were also changed as AP-42 often gives multiple values for different burner/boiler configurations. The new values are more consistent between pollutants.

The SOx uncontrolled values are now all calculated based on the fuel properties on sheet E. Previously there was a mixture of calculated and fixed values.



2.2 TECHNOLOGY CONTROL FACTORS

The first modifier of the uncontrolled emissions is a technology/fuel control factor. This factor is for the degree to which the emissions are controlled. For NOx and SOx these are derived from the US EIA Energy Outlook reports. This control factor changes with time as more systems are outfitted with emission controls and the control technology improves. The factors that are currently in the model are shown in the following figure.

Figure 2-1 NOx and SOx Control Factors

The calculated NOX factors are applied to coal, fuel oil, other carbon and natural gas combustion sources. The calculated SOx control factors are applied to coal and fuel oil combustion sources.

PM control factors are calculated by the model for coal and fuel oil emissions. Control factors for the other contaminants and the other fuel sources are all user inputs so they need to be set at the appropriate value for the time and region being modelled. These are found in rows 86 to 96 and columns B to J of sheet J.

The PM control factor for biomass powered generators are set to 0.20 based on the following discussion on control systems presented in AP-42 Chapter 1.6.

Currently, the four most common control devices used to reduce PM emissions from wood-fired boilers are mechanical collectors, wet scrubbers, electrostatic precipitators (ESPs), and fabric filters.

• The use of mechanical collectors (multiclones) provides particulate control for many wood-fired boilers. Often, two multiclones are used in series, allowing the first collector to remove the bulk of the dust and the second to remove smaller particles. The efficiency of this arrangement varies from 25 to 65 percent.

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• The most widely used wet scrubbers for wood-fired boilers are venturi scrubbers. With gas-side pressure drops exceeding 15 inches of water, particulate collection efficiencies of 85 percent or greater have been reported for venturi scrubbers operating on wood-fired boilers.

• ESPs are employed when collection efficiencies above 90 percent are required. When applied to wood-fired boilers, ESPs are often used downstream of mechanical collector precleaners which remove larger-sized particles. Collection efficiencies of 90 to 99 percent for PM have been observed for ESPs operating on wood-fired boilers.

• Fabric filters (i. e., baghouses) have had limited applications to wood-fired boilers. The principal drawback to fabric filtration, as perceived by potential users, is a fire danger arising from the collection of combustible carbonaceous fly ash. Steps can be taken to reduce this hazard, including the installation of a mechanical collector upstream of the fabric filter to remove large burning particles of fly ash (i. e., "sparklers"). Despite complications, fabric filters are generally preferred for boilers firing salt-laden wood. This fuel produces fine particulates with a high salt content having a quenching effect, thereby reducing fire hazards. Particle collection efficiencies are typically 80% or higher.

The user of the model can over ride the default values if a specific set of circumstances are being modelled.

2.3 COUNTRY CONTROL FACTORS

The second control factor that is applied to the calculation of the emissions is a region or country factor. This recognizes that control strategies may vary from region to region depending on local regulations. An issue for the model was that the control estimates applied for NOx, SOx, and PM were for the United States and did not necessarily represent the situation in other countries. Furthermore, the country factor could be different for the different fuels.

In this version of the model the country factor has been restricted to be active for only coal, fuel oil, other carbon and natural gas fuels. The primary concern is with respect to the emissions from coal fired facilities.

NOx and SOx emissions for coal fired power in Canada are reported by Transalta Utilities (Transalta, 2007), SaskPower (SaskPower, 2007), and by Ontario Power Generation (Ontario Power Generation, 2007)). The emissions reported by Transalta may include natural gas burning facilities. These emission factors are compared in the following table.

Table 2-2 Canadian NOx and SOx Coal Emission Rates

NOx SOx PMAP-42 Uncontrolled (kg/tonne) 10.85 18.03 42.6Transalta (controlled g/kWh) 8.67 7.39 0.12OPG (controlled g/kWh) 8.02 22.48 Not reportedSask (controlled g/kWh) 14.58 47.59 Not reported The reported values for NOx and SOx for Canadian coal fired stations are considerably higher that the model calculates. To account for this the Canadian factors in the model have been increased. The values in the model are shown in the following table. The Canada East values are the average of the Canada Central and West values. The effect of these factors is



to increase the emissions from coal, oil and natural gas power generation sources in Canada compared to the United States.

Table 2-3 Canadian Adjustment Factors

Canada East Canada Central Canada West NOx 2.76 2.43 3.09 SOx 2.28 2.58 1.99 PM 1.00 1.00 1.00 The impact of these changes for Canada on the average Canadian fuel mix is summarized in the following table. These result in small changes in GHG emissions (due to changes in methane, nitrous oxide and CO) and large increases in NOx and SOx.

Table 2-4 Impact of Changes on Average Canadian Electricity Mix

GHGenius 3.11 GHGenius 3.12 g CO2eq/GJ power produced NMOC 3.60 1.70 Ozone-weighted NMOC 2.19 0.97 CH4 52.26 54.99 CO 13.11 23.76 N2O 0.27 0.27 NOx as NO2 96.74 255.67 SOx 262.64 582.31 PM 16.42 17.02 PM10 8.62 7.84 PM2.5 4.89 4.10 CO2 73,921 73,963



3. OIL REFINING EMISSIONS The oil refining emissions in GHGenius are calculated by individual refining unit on sheet G. The calculation process is described as follows.

Emissions from process areas, such as catalytic cracking units, are estimated separately for each pollutant (NMOCs, CH4, CO, N2O, NOx, SO2, PM, and CO2) and each major type of product (gasoline, distillate fuel, residual fuel, and LPG). The basic input data are the controlled and uncontrolled emissions of each pollutant from each process area in a refinery, the fraction of throughput that is controlled, and the amount of throughput of each type of product in each process area. The uncontrolled emissions are from AP-42 and the control rate in LEM was estimated so that the total refinery emissions approximated those reported by the US EPA. From these data, the model calculates emissions of each pollutant per unit output of each type of product.

For the United States, the model calculates the total emissions for the domestic refining industry based on the calculated emission factors and the data on refinery production on sheet O. These calculated emissions were compared to other emission estimates for the United States (US EPA, 1997). This 1997 EPA report included actual data up to 1996 and had some forecasts through to 2010, however it is no longer published in the previous format so it is difficult to use this information as a benchmark.

In 2002 Environment Canada commissioned a benchmarking study of the Canadian refinery industry (Levelton, 2003), which reported on the emissions for both the US refining sector, and the Canadian industry. This information is now used to calibrate the model and the structure of the model has been changed to allow for regionalization so that different emissions can be projected for the US sector compared to the Canadian sector if necessary as well as the east, central, and west regions of each country.

The reported US refining emissions from the Levelton study were for the year 1999, which appears to be the most recent aggregated data available. The emissions are summarized in the following table both on an aggregate basis and on a per unit basis. The previous versions of the model overestimate the VOC emissions and underestimate the NOx, SOx and PM emissions.

Table 3-1 US Refinery Emissions – 1999

Previous GHGenius 1996

1999 Levelton estimate 1999 Levelton estimate

tonnes tonnes kg/klCO 181,340 181,021 0.21VOC 636,200 140,190 0.16NOx 66,001 237,072 0.28SOx 149,620 384,557 0.45PM10 18,450 42,676 0.05PM2.5 18,450 37,149 0.04 The data is available on a PADD basis and the estimated emissions for the regions in GHGenius are shown in the following table.



Table 3-2 US Refinery Emissions by GHGenius Region

US Total US East US Central US West kg/kl CO 0.21 0.46 0.21 0.09VOC 0.16 0.12 0.17 0.15NOx 0.28 0.25 0.30 0.22SOx 0.45 0.60 0.46 0.32PM10 0.05 0.05 0.05 0.04PM2.5 0.04 0.05 0.04 0.04 The regional relative factors for the emissions are calculated as the regional emission factors divided by the national factors and are summarized in the following table.

Table 3-3 US Refinery Regional Emission Adjustment Factors

US Total US East US Central US West kg/kl Adjustment Factor CO 0.21 2.19 1.00 0.43VOC 0.16 0.75 1.06 0.94NOx 0.28 0.89 1.07 0.79SOx 0.45 1.33 1.02 0.71PM10 0.05 1.00 1.00 0.80PM2.5 0.04 1.25 1.00 1.00

The degree to which the refining emissions are controlled in GHGenius has been manually adjusted to get the best fit between the model projections and the data reported by Levelton. The values in the model for 1999 are an exact match with those of the first column in the above table. The emission factors for N2O were not adjusted. The methane emissions were reduced by an order of magnitude to be better aligned with the values reported by the US EPA for the year 1994.

In previous versions of GHGenius there has not been any difference between the refinery emissions in the US and in Canada. The Levelton work showed that there are significant differences due to crude oil slates, refinery configurations, and regulations. The comparison of the emission factors for the two countries is shown in the following table. Canadian sulphur levels are about twice the US levels and the CO levels in Canada are about one half of the US levels. The other values are relatively close. Note the year of the data is different than the US data.

Table 3-4 Canadian vs. US Refinery Emissions – 2001

Levelton 1999 US estimate Levelton 2001 Canadian estimate kg/kl tonnes kg/klCO 0.21 11,336 0.10VOC 0.16 20,909 0.20NOx 0.28 27,286 0.27SOx 0.45 110,115 1.07PM10 0.05 4,941 0.06PM2.5 0.04 3,039 0.05



The regional relative factors for the emissions are calculated as the regional emission factors divided by the national factors and are summarized in the following table. These were balanced both regionally and nationally so some manual adjustment was required to achieve the best overall fit. The user can change these if it was desired to model a specific refinery or a future regulatory change.

Table 3-5 Canadian Refinery Regional Emission Adjustment Factors

Canada Total Canada East Canada Central Canada West kg/kl Adjustment Factor CO 0.10 0.45 0.86 0.37VOC 0.20 2.60 1.26 0.80NOx 0.27 1.45 0.99 0.59SOx 1.07 2.40 3.00 0.63PM10 0.06 1.46 1.55 0.78PM2.5 0.05 1.27 1.55 0.72

The impact of these changes is summarized in the following table. These results are found in Table 56 on the Upstream Results sheet in the model. The results are presented for the year 2007 and for the Canada average. The emissions are for the lifecycle up to the nozzle so they include more than just the refining emissions. The GHG emissions are lower because of the net impact of lower methane and carbon monoxide emissions at the refinery. SOx emissions are significantly higher.

Table 3-6 Comparison of Results GHGenius 3.11 and 3.12

GHGenius

3.11GHGenius

3.12GHGenius

3.11 GHGenius

3.12Fuel Gasoline (Low S) Hwy diesel g/GJ Fuel Carbon dioxide (CO2) 19,374 19,404 15,689 15,719 Non methane organic compounds (NMOCs) 39 37 13 12 Methane (CH4) 139 129 134 125 Carbon monoxide (CO) 43 19 39 16 Nitrous oxide (N2O) 1 1 1 1 Nitrogen oxides (NO2) 59 81 54 72 Sulphur oxides (SOx) 34 77 30 74 Particulate matter (PM) 6 9 5 6 HFC-134a (mg) 0 0 0 0 CO2-equivalent GHG emissions 22,607 22,426 18,732 18,586



4. OFF ROAD MOBILE EQUIPMENT The US EPA has developed a mobile source emissions inventory model for nonroad equipment (NONROAD), which covers all equipment except locomotives, aircraft, and commercial marine vessels. NONROAD2005 is the latest version of the NONROAD model and it supersedes all previous versions of this model. NONROAD2005 calculates past, present, and future emission inventories (i.e., tons of pollutant) for all nonroad equipment. Fuel types included in the model are: gasoline, diesel, compressed natural gas, and liquefied petroleum. The model estimates exhaust and evaporative hydrocarbons (HC), carbon monoxide (CO), oxides of nitrogen (NOx), particulate matter (PM), sulphur dioxide (SO2), and carbon dioxide (CO2).

The NONROAD2005 incorporates all of the known regulatory changes that apply to these engines and thus is the best tool available for determining the emission factors for GHGenius.

The model has been used to determine the appropriate emission factors for the vehicle and engines found on Sheet N as well it has been run for multiple years so that the performance of emissions over time could be determined and programmed into GHGenius. There are two categories of off road equipment that are not included in NONROAD and these are described below.

A more common approach to the rate of change of the emissions on sheet N has been incorporated in this version of the model. The uncontrolled emission rate is reported in rows 75-88 of sheet N. An exponential decay is assumed for all changes with the user specifying a base year when emissions start to decline (rows 124-137), the minimum value (rows 99-112), and the year when the emissions have been 95% controlled rows (143-156).

As part of this work the uncontrolled emission rates have been confirmed and estimates of the decay function have been made to reflect the best available in use emission data.

SOx emissions are calculated from the sulphur content of the fuel, the sum of exhaust and evaporative emissions, and the carbon and ozone weighted sum of the VOC emissions are calculated separately in the model.

4.1 TRAINS

Locomotive emissions are not included in AP-42. The US EPA did estimate the uncontrolled emissions for line haul locomotive emissions in 1997 and the forecasts for improvements over time. That information is summarized in the following table. The Tier 2 emissions apply to new engines and thus would phase in over time.

Table 4-1 EPA Line Haul Locomotive Emissions

NOx CO HC PM g/litre fuel

Pre 1973 engines 71.4 7.04 2.64 1.78Tier 2 (post 2004) 27.2 7.04 1.43 0.95 Environment Canada has published a series of reports on the emissions from the rail sector with the most recent report dated 2006 and containing information on rail emissions up to the year 2005 (Environment Canada, 2006). The emission factors are summarized in the following table.



Table 4-2 Railway Emission Factors- Freight Trains

NOx CO HC PM SO2 g/litre fuel

1990-2000 54.69 10.51 2.73 1.30 2.542001-2002 58.81 10.51 2.73 1.30 2.54

2003 53.17 10.81 2.34 1.19 2.372004 52.54 7.22 2.99 1.85 2.302005 50.48 7.17 3.01 1.83 2.33

Only the NOx emissions from the Environment Canada report are below the uncontrolled emissions reported earlier by the US EPA. In the following table the values from GHGenius 3.11 are compared to the factors from the EPA document. The new values for GHGenius 3.12 are shown as well.

Table 4-3 Comparison of Locomotive Emissions

NOx CO HC PM g/litre fuel Pre 1973 engines 71.4 7.04 2.64 1.78GHGenius 3.11 uncontrolled 59.14 0.75 2.53 1.39GHGenius 3.12 uncontrolled 71.4 7.0 2.60 1.78 The Environment Canada report uses emission factors for methane of 0.15 g/litre and for N2O of 1.1 g/litre. The N2O emission rate is also the IPCC default value. These values are now used for the uncontrolled emissions for locomotives. This results in about a 40% reduction in methane emissions but an increase of thirty times for the N2O emissions. The N2O emissions for locomotives are 13.75 times higher than Environment Canada uses for uncontrolled heavy-duty diesel engines and the IPPC notes a wide range in values of 14 to 86 g/GJ (0.5 to 3.3 g/l).

There is very little data available on aldehyde emissions from diesel engines. The US EPA published some information in 2001 (EPA, 2001) in which the aldehyde emissions were about 3.6% of the total hydrocarbon emissions over a range of fuels and engines. This value has been used in GHGenius 3.12.

For improvements over time it will be assumed that only NOx, HC and PM have control systems applied. The minimum values for NOx will be 0.4 times the uncontrolled rate, the minimum value for HC and PM will both be 0.5. The base year for the NOx is set to 1995 and 2005 for the HC and PM. The 95% control year is set to 2050 for all three contaminants. Note that for contaminants with a minimum value of 1.0 (no change over time) it is not necessary to specify the base year and the 95% controlled year.

The sulphur emissions are calculated from the fuel sulphur content. For this version of the model the sulphur for railroad and marine fuels is set to decline to 15 ppm by 2013. The model selects the appropriate value form a lookup table on sheet E. Previous versions of the model only considered onroad and offroad diesel with different schedules for reducing sulphur content of the fuel. This version includes a third fuel category for rail and marine and its corresponding schedule. This schedule is shown below.



Table 4-4 Sulphur in Fuel Schedule

1995 1998 2006 2007 2008 2010 2011 2012 2013 Sulphur, ppm wt On road 2200 300 150 15 15 15 15 15 15Off Road 2200 2200 1000 300 300 150 15 15 15Rail and Marine 2200 2200 2000 1000 300 300 250 150 15

The final aspect of the calculation of the GHG emissions for rail transport is an estimate of the indirect energy required to manufacture the train. The value that has been used in the model is 20% of the energy consumed by the train. This value is not well supported in the original LEM documentation. A quick calculation of the value is undertaken here.

The average fuel consumption of a locomotive in Canada is 666,000 litres/year (25,775 GJ) and the ratio of locomotives to freight cars is 1 to 30 (Railway Association of Canada). If it assumed that a locomotive has a weight of 200 tonnes and each rail car has a weight of 30 tonnes then there is a total weight of 1,100 tonnes. The manufacturing energy for heavy-duty vehicles in GHGenius is calculated and for Canada it amounts to 64,114 kJ/kg. The total energy required to manufacture this train is therefore 70,525 GJ.

If it is assumed that this train has a lifespan of 30 years then it it’s life it will consume 773,000 GJ of energy. The energy required to manufacture the train is therefore on the order of 10% of the energy used to manufacture the cars. Heavy-duty trucks in GHGenius have emissions associated with manufacturing the vehicles of about 3% of the operating emissions. Rail cars are designed and built to have longer life spans, so it is reasonable that the energy embedded in them is higher than it is for heavy-duty trucks. The value for the model has been reduced from 20% to 10% on the basis of these calculations.

The following table compares the results for trains from GHGenius 3.11 and 3.12. There is a large increase in non CO2 emissions, which are offset by a reduction in the indirect energy emissions.



Table 4-5 Comparison of Emissions for Trains 2007

GHGenius 3.11 GHGenius 3.12Device or process Train TrainFuel or feedstock diesel diesel g/GJ g/GJAldehydes (as HCHO) exhaust n.e. 1.13 Fuel evaporation or leakage 0.00 0.00 NMOC exhaust 59.52 59.19 Evaporation +NMOC exhaust 59.52 59.19 Carbon in evap. + NMOC exh. 51.07 50.79 Ozone-weighted total NMOC 33.33 33.15 CH4 (exhaust) 5.95 3.88 CO 19.42 181.10 N20 0.95 28.40 NOx (NO2) 1,208.70 1,315.38 SOx (SO2) 52.97 43.63 PM 16.56 43.18 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 68,303 67,980 Non-CO2 pollutants 419 8,885 Indirect energy: 18,608 9,340 Subtotal 87,329 86,206 Making the fuel: 18,732 15,499 GRAND TOTAL 106,061 101,705

4.2 MARINE VESSELS

The emissions in the model are estimated for coastal tankers and are used for all marine shipments. Data on these emissions is scarce but it is generally agreed that emissions (other than SOx) are a non linear function of the engine load. Some data has been published by Environment Canada, Lloyd’s Register, and the US Coast Guard and reviewed by the US EPA (2000). Guidance for methane and nitrous oxide is also available from the IPCC. This information is summarized in the following table.

Table 4-6 Marine Vessel Emission Factors

GHGenius 3.11

IPCC Lloyd’s Medium

Speed Engines

Lloyd’s Slow

Speed Engines

Environment

Canada

BC Ferries

GHGenius 3.12

g/litre fuel HC 6.12 - 2.5 2.3 0.5-1.2 2.5CH4 (exhaust) 0.61 0.27 0.27CO 12.83 - 7.3 8.2 0-9.7 4.9 8.0N2O (g/GJ) 0.95 2.0 2.0NOx (NO2) 32.74 - 54 76 48-179 68.7 75PM 2.4 - 1.0 1.5 1-16 2.0 1.5



The SOx emissions are calculated from the fuel sulphur content, which is determined by the model from the same lookup table as the rail fuel.

The energy required to build the vessels is maintained at 20%. It is difficult to find reasonable values for this parameter but it is plausible that ships are built to a more robust design criteria that rail engines.

The minimum values are set to 1.0 for all values. This assumes that no emission controls are applied (other than the fuel sulphur content). With this assumption the base year and the year for a 95% emissions reduction are not active components of the equations.

There are some changes in the emissions as a result of the different input values as shown in the following table. Hydrocarbon and CO emissions are reduced, and NOx and N2O emissions have increased. Emissions for making the fuel have increased due to the requirement for lower sulphur fuels being phased in. There is more consistency now between the rail and marine emissions, with only the N2O emissions still being significantly different.

Table 4-7 Comparison of Emissions for Tankers 2007

GHGenius 3.11 GHGenius 3.12Device or process Coastal Tanker Coastal TankerFuel or feedstock Diesel/fuel oil Diesel/fuel oil g/GJ g/GJAldehydes (as HCHO) exhaust n.e. 1.29 Fuel evaporation or leakage 0.00 0.00 NMOC exhaust 133.29 53.45 Evaporation +NMOC exhaust 133.29 53.45 Carbon in evap. + NMOC exh. 114.37 45.86 Ozone-weighted total NMOC 66.64 26.73 CH4 (exhaust) 13.33 6.47 CO 307.60 191.76 N20 0.95 2.00 NOx (NO2) 688.68 1,797.74 SOx (SO2) 449.05 45.28 PM 39.38 35.95 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 70,118 70,580 Non-CO2 pollutants 574 756 Indirect energy: 18,608 18,681 Subtotal 89,300 90,016 Making the fuel: 13,821 15,499 GRAND TOTAL 103,120 105,515

4.3 VEHICLES

The US EPA has developed a NONROAD2005 emissions model. NONROAD2005 calculates past, present, and future emission inventories (i.e., tons of pollutant) for all nonroad equipment categories except commercial marine, locomotives, and aircraft. Fuel types included in the model are: gasoline, diesel, compressed natural gas, and liquefied petroleum. The model estimates exhaust and evaporative hydrocarbons (HC), carbon



monoxide (CO), oxides of nitrogen (NOx), particulate matter (PM), sulphur dioxide (SO2), and carbon dioxide (CO2).

Specific vehicles were modelled in NONROAD over the 1995 to 2025 time period to determine the projected emissions performance over time. The GHGenius model has been set to try and follow these emissions.

4.3.1 Scrapers

Diesel powered scrapers are included in GHGenius and are utilized in the Coal and Uranium production pathways. The emissions performance projected by NONROAD is shown in the following figures. As with the other pathways the SOx emissions are calculated from the fuel composition.

Figure 4-1 Scraper Emissions – NOx and CO

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Figure 4-2 Scraper Emissions – PM and HC

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It is not clear what the issue is with the PM emissions after 2010 but it will be assumed that they remain at the 1.5 g/litre level for GHGenius modelling purposes.

The IPCC provides emission estimates of methane and nitrous oxide emissions for diesel engines. These are 4.15 g/GJ of methane and 28.6 g/GJ for nitrous oxide. These values will be used in the model.

The current uncontrolled values in GHGenius are compared to the new values based on these results in the following table.

Table 4-8 Uncontrolled Scraper Emissions

GHGenius 3.11 GHGenius 3.12 g/litre Aldehydes (as HCHO) exhaust 1.16 0.12Evaporative VOCs 0.00 0.0TOCs exhaust (incl. HCHO, CH4) 3.44 3.30CH4 (exhaust) 0.10 0.16CO 10.15 21.50N2O (G/GJ) 0.95 28.60NOx (NO2) 31.02 40.00SOx (SO2) (g/GJ) calculated calculatedPM 3.27 3.80 Based on the NONROAD results the model parameters that have been set to best fit the decline in emissions over time are summarized in the following table.



Table 4-9 Parameters for Modelling Emission Reductions

Minimum Value/Uncontrolled Value

Base Year 95% reduction Year

kg/kLAldehydes (as HCHO) exhaust

0.20 1995 2020

Evaporative VOCs 1.00 1995 2020TOCs exhaust (incl. HCHO, CH4)

0.20 1995 2020

CH4 (exhaust) 0.20 1995 2020CO 0.10 1995 2020N2O (G/GJ) 1.00 1995 2020NOx (NO2) 0.04 1995 2020PM 0.40 1995 2010 There are some changes in the emissions as a result of the different input values as shown in the following table. The higher N2O levels have a significant impact on the GHG emissions. The HC, NOx and sulphur emissions are lower as well.

The energy required to manufacture the vehicle has been 0.45 times the fuel consumption in previous versions of GHGenius and in LEM. The supporting data for this value in LEM is much more defensible than the assumed values for ships and trains so no changes have been made for this value here.

Table 4-10 Comparison of Emissions for Scrapers 2007

GHGenius 3.11 GHGenius 3.12Device or process Scrapers ScrapersFuel or feedstock Diesel Diesel g/GJ g/GJAldehydes (as HCHO) exhaust 30.07 1.21 Fuel evaporation or leakage 0.00 0.00 NMOC exhaust 80.93 31.68 Evaporation +NMOC exhaust 80.93 31.68 Carbon in evap. + NMOC exh. 69.44 27.18 Ozone-weighted total NMOC 45.32 17.74 CH4 (exhaust) 8.09 1.61 CO 262.50 174.47 N20 0.95 28.60 NOx (NO2) 704.10 277.25 SOx (SO2) 52.97 13.09 PM 58.02 44.69 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 67,731 68,079 Non-CO2 pollutants 464 8,900 Indirect energy: 41,867 42,032 Subtotal 110,062 119,011 Making the fuel: 18,732 15,716 GRAND TOTAL 128,794 134,726



4.3.2 Wheeled Loaders

Wheeled loaders are used in a number of production pathways both in field type applications and at production plants. The NONROAD emission results are shown in the following two figures. It can be seen that the emissions are quite similar, but not identical, to those of the scrapers. The most significant difference being that NOx emissions do not decline to quite the same level in the wheeled loaders as they do with the scrapers.

Figure 4-3 NOx and CO Emissions Wheeled Loaders

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Figure 4-4 HC and PM Emissions Wheeled Loaders

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Given the similarity between the loaders and the scrapers, the uncontrolled emissions will be set the same in both cases. The minimum value for NOx for the wheeled loaders will be set to 1.6 times higher than the minimum for the scraper and all of the improvement rates will be set the same.

No changes are made to the indirect energy ratio for the loaders. In the following table the results from GHGenius 3.11 are compared to those calculated here.



Table 4-11 Comparison of Emissions for Wheeled Loaders 2007

GHGenius 3.11 GHGenius 3.12Device or process Wheeled Loaders Wheeled LoadersFuel or feedstock Diesel Diesel g/GJ g/GJAldehydes (as HCHO) exhaust 22.25 1.21 Fuel evaporation or leakage 0.00 0.00 NMOC exhaust 141.97 31.68 Evaporation +NMOC exhaust 141.97 31.68 Carbon in evap. + NMOC exh. 121.81 27.18 Ozone-weighted total NMOC 79.50 17.74 CH4 (exhaust) 14.20 1.61 CO 306.12 174.47 N20 0.95 28.60 NOx (NO2) 874.62 293.03 SOx (SO2) 52.97 13.09 PM 62.28 44.69 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 67,442 68,079 Non-CO2 pollutants 592 8,900 Indirect energy: 41,867 42,032 Subtotal 109,901 119,011 Making the fuel: 18,732 15,716 GRAND TOTAL 128,633 134,726

4.3.3 Off Road Trucks

The NONROAD emission forecasts for off road trucks are shown in the following two figures. The emissions from these vehicles are not used extensively in the model since the emissions for on road trucks are used in most cases. While it appears that the forecasts are quite similar to the scrapers and loaders, there are some significant differences.



Figure 4-5 NOx and CO Emissions Off Road Trucks

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Figure 4-6 HC and PM Emissions Off Road Trucks

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PM exhaust

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The THC exhaust emissions are very similar to those of the scraper for both the initial values and the final values and they will be set to the same as the scraper, as will the methane and N2O emissions. There is some variation in the PM emissions with the levels starting at about 80% of the scarper value but ultimately reaching the same level. The NOx values are similar until about 2017 when the rate of improvement for the trucks slows down and the minimum value of about three times higher than the scraper. The CO levels have a similar initial value but drop to one half of the minimum value for the scrapers. All of these differences have been incorporated into the rates of decline and the minimum values.

No changes are made to the indirect energy ratio for the off road trucks but the value in the model is much higher than the value calculated by the model for on-road trucks. This is a function of the duty cycle and it is basically assumed that off road vehicles consume less energy in their lifetime than the on road trucks and therefore the manufacturing energy is amortized over a smaller amount of consumed energy. There is some logic to this argument but it is difficult to quantify the differences. The default values in GHGenius are believed to be conservative, i.e. they result in emissions that may be higher than actual emissions. In the following table the results from GHGenius 3.11 are compared to those calculated here.

Table 4-12 Comparison of Emissions for Off Road Trucks 2007

GHGenius 3.11 GHGenius 3.12Device or process Off Road Trucks Off Road TrucksFuel or feedstock Diesel Diesel g/GJ g/GJAldehydes (as HCHO) exhaust 24.02 1.21 Fuel evaporation or leakage 0.00 0.00 NMOC exhaust 58.95 31.68 Evaporation +NMOC exhaust 58.95 31.68 Carbon in evap. + NMOC exh. 50.58 27.18 Ozone-weighted total NMOC 33.01 17.74 CH4 (exhaust) 5.90 1.61 CO 383.07 105.55 N20 0.95 28.60 NOx (NO2) 778.97 332.61 SOx (SO2) 52.97 13.09 PM 37.62 42.90 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 67,674 68,192 Non-CO2 pollutants 418 8,900 Indirect energy: 41,867 42,032 Subtotal 109,959 119,124 Making the fuel: 18,732 15,716 GRAND TOTAL 128,691 134,840

4.3.4 Farm Tractors

Farm tractors in the model can be either fuelled by gasoline or by diesel fuel, although most of the default inputs in the model assume diesel powered tractors. Emission projections for both are available in NONROAD and are reviewed below.



4.3.4.1 Diesel

In the following two figures the emissions projections for diesel fuelled farm tractors from the NONROAD model are shown. As expected from the emission data for the other diesel powered vehicles the emission projections follow a similar future path but there are some differences in the beginning and ending values.

Figure 4-7 NOx and CO Emissions Diesel Farm Tractors

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Figure 4-8 HC and PM Emissions Diesel Farm Tractors

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The same values (IPCC defaults for off road diesel equipment) will be used for methane and N2O emissions. The THC rates are about twice the starting values for scrapers and the ending value is about 1.25 times that of the scrapers. The initial CO value is 40% higher than it is for the scraper and the final value double the scraper. The initial NOx value is 10% higher than the scraper but the final value is three times that of the scraper. The initial PM value is 70% higher than it is for the scraper but the final value is similar.

No change has been made to the indirect energy estimation. Like all of the off road vehicles it is believed to be conservative.

The results of these changes is shown in the following table and compared to the results from GHGenius 3.11. Directionally the results are similar to those presented for the other diesel powered off road vehicles.



Table 4-13 Comparison of Emissions for Diesel Tractors 2007

GHGenius 3.11 GHGenius 3.12Device or process Diesel Tractors Diesel TractorsFuel or feedstock Diesel Diesel g/GJ g/GJAldehydes (as HCHO) exhaust 37.54 2.18 Fuel evaporation or leakage 0.00 0.00 NMOC exhaust 205.35 58.61 Evaporation +NMOC exhaust 205.35 58.61 Carbon in evap. + NMOC exh. 176.19 50.29 Ozone-weighted total NMOC 115.00 32.82 CH4 (exhaust) 20.54 1.46 CO 369.24 244.26 N20 0.95 28.60 NOx (NO2) 912.11 426.51 SOx (SO2) 52.97 13.09 PM 97.13 100.28 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 67,027 67,729 Non-CO2 pollutants 725 8,897 Indirect energy: 45,507 45,686 Subtotal 113,260 122,311 Making the fuel: 18,732 15,716 GRAND TOTAL 131,992 138,026

4.3.4.2 Gasoline

In the following two figures the emissions projections for gasoline fuelled farm tractors from the NONROAD model are shown. These emission projections are quite different from those presented for the various diesel powered vehicles.



Figure 4-9 NOx, HC Exhaust and CO Emissions Gasoline Farm Tractors

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Figure 4-10 HC Evaporative and PM Emissions Gasoline Farm Tractors

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The values in GHGenius have been adjusted to best fit the curves shown above. The IPCC factor for agricultural off road engines are used for N2O (2 g/GJ) and methane (80 g/GJ).



Table 4-14 Comparison of Emissions for Gasoline Tractors 2007

GHGenius 3.11 GHGenius 3.12Device or process Gasoline Tractors Gasoline TractorsFuel or feedstock Gasoline Gasoline g/GJ g/GJAldehydes (as HCHO) exhaust 23.65 10.04 Fuel evaporation or leakage 185.68 47.61 NMOC exhaust 396.40 210.73 Evaporation +NMOC exhaust 582.08 258.34 Carbon in evap. + NMOC exh. 649.85 260.65 Ozone-weighted total NMOC 535.66 246.44 CH4 (exhaust) 59.46 49.92 CO 11,272.03 16,704.55 N20 3.79 0.80 NOx (NO2) 458.15 225.16 SOx (SO2) 1.28 1.28 PM 18.95 5.77 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 46,995 39,955 Non-CO2 pollutants 2,424 1,296 Indirect energy: 45,507 45,686 Subtotal 94,926 86,937 Making the fuel: 22,607 22,426 GRAND TOTAL 117,534 109,363

4.4 STATIONARY ENGINES

There are emissions projections for stationary gasoline and diesel engines within NONROAD as well as the transportation vehicles. The emissions projections for both fuels are shown in the following sections.

4.4.1 Gasoline

The following two figures show the results for the stationary gasoline engines. The CO emissions show an increase, which is difficult to rationalize so these emissions have been kept flat in GHGenius.



Figure 4-11 HC and CO Emissions Gasoline Engines

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Figure 4-12 NOx and PM Emissions Gasoline Engines

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The values in GHGenius have been adjusted to best fit the curves shown above. The IPCC factor for industrial off road engines are used for N2O (2 g/GJ) and methane (120 g/GJ).



Table 4-15 Comparison of Emissions for Gasoline Stationary Engines 2007

GHGenius 3.11 GHGenius 3.12Device or process Gasoline Engines Gasoline EnginesFuel or feedstock Gasoline Gasoline g/GJ g/GJAldehydes (as HCHO) exhaust 30.12 33.76 Fuel evaporation or leakage 400.21 299.42 NMOC exhaust 812.02 430.42 Evaporation +NMOC exhaust 1,212.23 729.83 Carbon in evap. + NMOC exh. 1,364.16 867.97 Ozone-weighted total NMOC 1,112.17 654.98 CH4 (exhaust) 121.80 299.42 CO 26,981.80 4,160.00 N20 3.79 0.80 NOx (NO2) 615.51 140.00 SOx (SO2) 0.88 1.28 PM 29.48 7.00 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 19,511 56,736 Non-CO2 pollutants 3,733 6,536 Indirect energy: 0 0 Subtotal 23,245 63,272 Making the fuel: 22,607 22,426 GRAND TOTAL 45,852 85,699

4.4.2 Diesel Fuel

In GHGenius there are two sets of emissions factors for large stationary engines and they have slightly different default values. As part of this work both have been set to the same values. The emissions projections from NONROAD are shown in the following figures.



Figure 4-13 NOx and CO Emissions Diesel Engines

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Figure 4-14 HC and PM Emissions Diesel Engines

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The values in GHGenius have been adjusted to best fit the curves shown above. The IPCC factor for industrial off road engines are used for N2O (28.6 g/GJ) and methane (4.15 g/GJ).



Table 4-16 Comparison of Emissions for Stationary Diesel Engines 2007

GHGenius 3.11 GHGenius 3.12Device or process Diesel Engines Diesel EnginesFuel or feedstock Diesel Diesel g/GJ g/GJAldehydes (as HCHO) exhaust 0.03 1.95 Fuel evaporation or leakage 0.00 0.00 NMOC exhaust 38.76 54.34 Evaporation +NMOC exhaust 38.76 54.34 Carbon in evap. + NMOC exh. 33.26 46.62 Ozone-weighted total NMOC 21.71 30.43 CH4 (exhaust) 4.30 4.15 CO 348.57 233.96 N20 0.95 28.60 NOx (NO2) 1,123.92 484.15 SOx (SO2) 36.28 13.09 PM 20.55 81.82 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 67,844 67,803 Non-CO2 pollutants 384 8,953 Indirect energy: 0 0 Subtotal 68,229 76,756 Making the fuel: 18,732 15,716 GRAND TOTAL 86,961 92,472



5. COMBUSTION EMISSIONS There are three groups of emissions calculated for devices used in the production of various fuels in GHGenius. These are industrial boilers, using solid, liquid or gaseous fuels, building heaters using liquid or gaseous fuels, and engine driven compressors. The baseline emissions for all of these fuels are derived from the US EPA AP-42 and from the IPCC 2006 good practice guidelines where AP-42 data is missing for methane and nitrous oxide. Estimates of how these emissions may change over time have been made using the exponential decay structure as used for the internal combustion devices. The input data, assumptions, and results are discussed in the following sections.

5.1 INDUSTRIAL BOILERS

There are three types of fuels used in industrial boilers in the model, solid, liquid, and gaseous. Industrial boilers can also vary considerably in size and design so some compromise on the emission factors has been required to select a single value for each type of fuel. The data is discussed below.

5.1.1 Solid Fuels

The combustion of three solid fuels are modelled in GHGenius, coal, petroleum coke, and wood waste. The uncontrolled emission factors for coal and biomass were reported in Table 2-1 for electric power generators. The same values will be used here for the coal and the wood (except the units for wood are different). For the petroleum coke the emission factors are derived from the anthracite combustion AP-42 emission factors.

It has been assumed that the only emissions that are controlled are NOx, SOx (for coal and coke only) and PM. Control factors have been applied that are similar to those used for power generation in the United States. The structure of the model allows the other emissions to be controlled as well if the user wishes to.

The results are compared to those from version 3.11 in the following table. There are small changes in the results from the two versions, primarily due to the different assumptions about the implementation of control strategies.



Table 5-1 Comparison of Emissions for Solid Fuel Industrial Boilers 2007

Fuel or feedstock Coal Petroleum Coke Wood GHGenius Version 3.11 3.12 3.11 3.12 3.11 3.12 g/GJ Aldehydes (as HCHO) exhaust 3.31 0.02 n.e. 0.02 2.29 2.29 Fuel evaporation or leakage 0.00 0.00 0.00 0.00 0.00 0.00 NMOC exhaust 1.22 0.41 2.86 0.29 7.31 7.73 Evaporation +NMOC exhaust 1.22 0.41 2.86 0.29 7.31 7.73 Carbon in evap. + NMOC exh. 0.73 0.24 1.71 0.17 3.66 3.87 Ozone-weighted total NMOC 0.79 0.26 1.86 0.19 4.75 5.03 CH4 (exhaust) 0.81 0.81 0.57 0.57 9.03 29.90 CO 10.13 10.13 28.56 7.14 257.97 257.97 N20 3.32 1.50 3.32 1.50 5.59 4.00 NOx (NO2) 293.06 173.70 142.78 122.43 94.59 94.59 SOx (SO2) 292.12 267.54 173.62 159.01 10.75 92.78 PM 633.21 151.25 28.79 106.60 23.22 35.17 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 88,253 89,886 94,035 93,854 0 0 Non-CO2 pollutants 1,045 473 1,040 468 1,493 1,867 Indirect energy: 0 0 0 0 0 0 Subtotal 89,299 90,359 95,075 94,322 1,493 1,867 Making the fuel: 2,671 2,690 12,509 12,608 -5,943 -5,866 GRAND TOTAL 91,969 93,048 107,584 106,930 -4,451 -3,999

5.1.2 Gaseous Fuels

Natural gas and refinery gas are both included as fuels for industrial boilers. The emission factors for natural gas boilers were also used for power generation and the same values have been used here. The refinery fuel emission factors are based on the natural gas emission factors with small adjustments for the different composition of the fuel.

The comparison of the calculated emissions between the two versions of the model is shown in the following table.



Table 5-2 Comparison of Emissions for Gaseous Fuel Industrial Boilers 2007

Fuel or feedstock Natural Gas Refinery Gas GHGenius Version 3.11 3.12 3.11 3.12 g/GJ Aldehydes (as HCHO) exhaust 0.17 0.00 0.16 0.00 Fuel evaporation or leakage 9.46 9.46 9.58 9.58 NMOC exhaust 1.18 3.69 3.98 7.55 Evaporation +NMOC exhaust 10.64 13.14 13.56 17.13 Carbon in evap. + NMOC exh. 7.79 9.79 10.48 13.33 Ozone-weighted total NMOC 1.74 2.74 1.59 3.02 CH4 (exhaust) 1.28 0.97 0.50 0.38 CO 14.83 35.58 14.41 34.58 N20 0.95 0.02 0.94 0.02 NOx (NO2) 39.53 67.03 52.21 88.53 SOx (SO2) 0.26 0.26 4.90 4.90 PM 5.80 3.22 5.64 3.13 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 50,073 50,041 53,378 53,344 Non-CO2 pollutants 499 363 365 234 Indirect energy: 0 0 0 0 Subtotal 50,572 50,404 53,743 53,577 Making the fuel: 7,193 7,258 8,425 8,491 GRAND TOTAL 57,765 57,662 62,168 62,069

5.1.3 Liquid Fuels

The emissions for crude oil combustors, fuel oil and LPG furnaces are also calculated in the model. The US EPA AP-42 is the source for these emission factors. The emission factors for residual oil have been used for both the crude oil and fuel oil columns. A control factor has been applied to the NOx emissions but not to the other emission factors.

The comparison of the results between the two versions of GHGenius is shown in the following table. The largest change has been in sulphur emissions where the emissions are now calculated based on the fuel sulphur content rather than a fixed value from AP-42.



Table 5-3 Comparison of Emissions for Liquid Fuel Industrial Boilers 2007

Fuel or feedstock Crude Oil Fuel Oil LPG GHGenius Version 3.11 3.12 3.11 3.12 3.11 3.12 g/GJ Aldehydes (as HCHO) exhaust 0.00 0.00 0.00 0.00 n.e. 0.00 Fuel evaporation or leakage 0.00 0.00 0.00 0.00 9.94 9.94 NMOC exhaust 0.80 0.87 0.80 0.81 2.00 1.46 Evaporation +NMOC exhaust 0.80 0.87 0.80 0.81 11.95 11.40 Carbon in evap. + NMOC exh. 0.69 0.74 0.69 0.70 9.73 9.30 Ozone-weighted total NMOC 0.40 0.43 0.40 0.41 2.92 2.62 CH4 (exhaust) 2.87 3.09 2.87 2.87 0.40 0.94 CO 14.37 15.45 14.37 14.37 15.26 15.26 N20 0.95 0.01 0.95 0.01 0.95 4.20 NOx (NO2) 105.41 117.15 105.41 109.15 60.28 46.73 SOx (SO2) 193.45 17.72 196.12 19.33 0.28 0.28 PM 13.76 39.01 14.45 36.35 2.83 2.83 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 69,947 69,873 71,094 71,032 59,532 59,532 Non-CO2 pollutants 354 170 354 159 302 1,322 Indirect energy: 0 0 0 0 0 0 Subtotal 70,301 70,044 71,448 71,191 59,834 60,854 Making the fuel: 9,921 9,999 13,821 13,707 12,373 12,207 GRAND TOTAL 80,222 80,042 85,269 84,898 72,207 73,060

5.2 BUILDING HEATERS

Emission rates for building heaters are included in GHGenius for natural gas, diesel fuel and the biodiesel products. There are difference in the AP-42 emission factors between these heaters and the industrial boilers.

5.2.1 Gaseous Fuels

There are some differences in the emission factors between natural gas industrial boilers and heaters. Some small changes have been made to the emission factors in version 3.12 and the future control assumptions are different.



Table 5-4 Comparison of Emissions for Natural Gas Building Heaters 2007

Fuel or feedstock Natural Gas GHGenius Version 3.11 3.12 g/GJ Aldehydes (as HCHO) exhaust n.e. 0.00 Fuel evaporation or leakage 9.46 9.46 NMOC exhaust 2.25 3.69 Evaporation +NMOC exhaust 11.70 13.14 Carbon in evap. + NMOC exh. 8.64 9.79 Ozone-weighted total NMOC 2.16 2.74 CH4 (exhaust) 1.14 0.97 CO 8.47 16.94 N20 0.95 0.95 NOx (NO2) 32.48 32.12 SOx (SO2) 0.26 0.26 PM 0.51 3.22 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 50,095 50,070 Non-CO2 pollutants 496 492 Indirect energy: 0 0 Subtotal 50,591 50,563 Making the fuel: 7,405 7,471 GRAND TOTAL 57,995 58,034

5.2.2 Liquid Fuels

There is very little information available on the emissions performance of biodiesel used in furnaces. A NREL report (NREL, 2004) did find lower NOx and CO emissions with biodiesel compared to diesel fuel but there was some inconsistency with the results. For this update the same emission factors have been used for biodiesel and diesel fuel with the exception of sulphur, which is calculated based on the fuel properties.

The results from the two versions of the model are summarized in the following table. The biodiesel results are presented for canola biodiesel and the emissions resulting from making the fuel will vary with the biodiesel pathway but the combustion emissions are the same for each biodiesel fuel.



Table 5-5 Comparison of Emissions for Liquid Fuel Building Heaters 2007

Fuel or feedstock Diesel Fuel Canola Biodiesel GHGenius Version 3.11 3.12 3.11 3.12 g/GJ Aldehydes (as HCHO) exhaust n.e. 0.00 n.e. 0.00 Fuel evaporation or leakage 0.00 0.00 0.00 0.00 NMOC exhaust 2.57 2.57 1.96 1.96 Evaporation +NMOC exhaust 2.57 2.57 1.96 1.96 Carbon in evap. + NMOC exh. 2.21 2.21 1.51 1.51 Ozone-weighted total NMOC 1.44 1.44 0.98 0.98 CH4 (exhaust) 5.52 5.52 5.78 5.78 CO 15.51 15.51 16.24 16.24 N20 0.86 0.16 0.95 0.16 NOx (NO2) 42.82 45.06 44.81 47.15 SOx (SO2) 52.97 13.09 0.00 0.00 PM 7.77 1.24 8.13 1.30 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 68,514 68,532 0 0 Non-CO2 pollutants 383 166 374 130 Indirect energy: 0 0 0 0 Subtotal 68,897 68,698 374 130 Making the fuel: 18,732 15,716 17,352 17,737 GRAND TOTAL 87,629 84,413 17,726 17,867

5.3 COMPRESSORS

Natural gas turbines or natural gas reciprocating engines can drive compressors used in pipeline systems. The EPA updated the emission factors for these classes of equipment in 2000 and the emission factors are different than previously used in GHGenius. The impact of the revised emission factors is shown in the following table. The emission factors for a lean burn 4 stroke engine have been selected from AP-42 for this pathway.

The comparison of the emissions between the two versions of GHGenius is presented in the following table.



Table 5-6 Comparison of Emissions for Compressors 2007

Fuel or feedstock Gas Turbine Gas Engine GHGenius Version 3.11 3.12 3.11 3.12 g/GJ Aldehydes (as HCHO) exhaust 0.00 0.04 25.82 25.82 Fuel evaporation or leakage 9.46 9.46 9.46 9.46 NMOC exhaust 0.86 1.03 38.01 94.67 Evaporation +NMOC exhaust 10.32 10.49 47.47 104.13 Carbon in evap. + NMOC exh. 7.53 7.67 37.25 82.58 Ozone-weighted total NMOC 1.61 1.68 16.47 39.13 CH4 (exhaust) 21.95 3.70 497.75 537.91 CO 301.23 16.45 253.90 92.63 N20 1.90 0.00 1.90 2.00 NOx (NO2) 103.88 64.20 830.04 730.51 SOx (SO2) 0.26 0.26 0.26 0.26 PM 18.03 2.84 19.80 0.03 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 49,533 50,073 48,186 48,218 Non-CO2 pollutants 1,226 257 11,218 12,094 Indirect energy: 0 0 0 0 Subtotal 50,759 50,329 59,404 60,313 Making the fuel: 7,193 7,258 7,193 7,258 GRAND TOTAL 57,953 57,587 66,598 67,570

The model has emission calculations for the use of hydrogen in a gas turbine and an internal combustion engine. The emission factors for these systems are not derived from AP-42 and are a carry over from LEM. These emissions are not used in the rest of the model and no changes have been made to emission factors.



6. PROCESS EMISSIONS There are emission factors for many of the fuel production processes in the model. These factors apply to the emissions from non-combustion sources within the processes. These emissions could be from fugitive sources or resulting from chemical reactions in the process. There are no EPA AP-42 emission factors for any of the processes (other than oil refining which was dealt with earlier) that are currently included in GHGenius, so information has been derived from other sources. This version of the model has been changed so that there is as much consistency as possible in terms of the emission factors that are applied to similar processes. The data from sheet N generally goes to the Upstream Results sheet for incorporation into the rest of the model.

6.1 PETROLEUM REFINERIES

The emissions calculated for each of the refinery products on sheet N are derived from emission and process data on sheet G. These emissions were dealt with in an earlier section of the report. All of the factors that would influence the emissions over time are found on sheet G, so no control factor data is found on this sheet for the refined petroleum products. The results of the emission changes on sheet G can be seen in the emission data shown below, which is extracted from sheet N. NOx, SOx, and PM emissions are higher than in previous versions and the VOC emissions are lower as a result of the regionalization of the emissions data undertaken as part of this work.

Table 6-1 Comparison of Process Emissions for Gasoline and Diesel 2007

Fuel or feedstock Gasoline Diesel GHGenius Version 3.11 3.12 3.11 3.12 g/GJ Aldehydes (as HCHO) exhaust n.e. n.e. n.e. n.e.Fuel evaporation or leakage 5.96 3.79 4.85 3.00 NMOC exhaust 0.00 0.00 0.00 0.00 Evaporation +NMOC exhaust 5.96 3.79 4.85 3.00 Carbon in evap. + NMOC exh. 4.94 3.15 4.03 2.49 Ozone-weighted total NMOC 4.47 2.85 3.64 2.25 CH4 (exhaust) 13.76 2.53 12.21 2.23 CO 7.75 2.93 4.74 1.82 N20 0.56 0.56 0.39 0.39 NOx (NO2) 2.24 8.64 1.78 7.00 SOx (SO2) 5.51 41.91 4.33 41.77 PM 0.80 2.75 0.48 1.65 Calculated Emission Factors, g/GJ, CO2 Or CO2 Equivalents: CO2 964 977 622 632 Non-CO2 pollutants 463 227 376 167 Indirect energy: 0 0 0 0 Subtotal 1,428 1,204 999 799 Making the fuel: 144 141 92 90 GRAND TOTAL 1,572 1,345 1,091 889



6.2 ETHANOL PRODUCTION

The use of energy within the ethanol plants will result in emissions of NOx, SOx and some PM and VOC depending on the process fuels used. These emissions are calculated by the model based on the fuel consumed in the production of the fuel and the emission factors described in section 5 of the report.

Non-energy related emissions from ethanol plants will be composed of VOC emissions from fermentation, distillation, storage and loadout of the products and PM emissions from traffic, grain handling, drying systems, and cooling towers. These emissions are estimated from the emission factors found on sheet N in columns AJ to AO. AP-42 does not have emission factors for fuel ethanol plants, only for estimating the emissions from beverage alcohol and those emission factors are incomplete. There are also emission factors for grain elevators, but this would only partially cover the emissions from a fuel ethanol production facility.

A significant amount of information on individual plants in the United States can be found in the literature as a result of the permitting process that most US ethanol plants have to undertake prior to construction. These plants are generally designed to meet the minor source requirements of the US EPA. These requirements can be met a number of different ways but essentially plants have been designed to emit less than 100 tons of an individual contaminant per year (recently increased to 250 tpy). The same emission limit is applied no matter what size the ethanol plant is, so large plants have lower per unit emissions. Information on Canadian plants is not as available as NPRI data does not include production information and only one plant was required to file data in 2006, the last year of public data.

Brady and Pratt (2007) have published information on VOC emissions from dry mill ethanol plants. This data is not directly correlated to production information but it does appear that they data supports the 100 tpy emissions limit for VOC emissions with emissions controls employed.

The emission factors for PM and VOC will be estimated based on a 200 million litre/year emitting 80% of the allowed emissions. The VOC emissions will be assumed to be met with an 80% overall emission reduction. This should be a conservative estimate since plants almost twice this size are able to meet the 100 tpy limit in the US. The assumed emission factors are summarized in the following table. These are used for the corn and wheat pathways.

Table 6-2 Ethanol Process Emission Factors

PM10 PM2.5 VOCUncontrolled 15 g/GJ 5 g/GJ 75 g/GJControlled 15 g/GJ 5 g/GJ 15 g/GJ Emission factors for the other ethanol pathways are not as easy to estimate since they are not in commercial operation in North America. For the cellulosic and sugar cane pathways it will be assumed that the process emissions are one half of those for the grain plants since these plants will still have emissions from feedstock handling, fermentation and distillation but probably not from co-product drying and recovery. The rate of reduction in the VOC emissions for these pathways has also been reduced. Since these plants burn solid fuels the energy related emissions will be higher than the plants that burn natural gas.

The process emissions from a sugar beet plant are likely to be different again from the other ethanol plants. PM emissions are likely lower since the moisture content of the feedstock is quite high, although the feedstock is dirty. VOC emissions from fermentation and distillation



will be similar and there may be both PM and VOC emissions from beet pulp drying. It has been assumed that PM emissions are 50% of those of the grain plants and the VOC emissions are the same as the grain ethanol plants.

These emission factors are significantly higher than those in the previous versions of GHGenius. They are probably quite conservative. While the increases in process emissions are a large percentage change over previous model versions, these emissions are a relatively small part of the total lifecycle emissions. The emissions of the air contaminants per GJ of fuel delivered are summarized in the following table for corn ethanol and gasoline. The negative emissions in the following table are a result of co-product credits. The high NOx emissions for corn ethanol are a function of fertilizer application and are not urban combustion emissions.

Table 6-3 Comparison of Results GHGenius 3.11 and 3.12 Corn Ethanol

GHGenius

3.11GHGenius

3.12GHGenius

3.11 GHGenius

3.12Fuel Gasoline (Low S) Corn Ethanol g/GJ Fuel Carbon dioxide (CO2) 19,374 19,404 31,472 31,470 Non methane organic compounds (NMOCs) 39 37 18 22 Methane (CH4) 139 129 -17 -16 Carbon monoxide (CO) 43 19 -3 -42 Nitrous oxide (N2O) 1 1 20 20 Nitrogen oxides (NO2) 59 81 177 182 Sulphur oxides (SOx) 34 77 26 48 Particulate matter (PM) 6 9 16 22 HFC-134a (mg) 0 0 3 2 CO2-equivalent GHG emissions 22,607 22,426 37,169 37,355

6.3 BUTANOL

Butanol production through fermentation is not practiced on a commercial scale today. Conceptually the process is similar to producing ethanol from corn. The VOC emissions profile will be different as butanol has a lower vapour pressure than ethanol but other products such as acetone and hydrogen can be produced. The two stage nature of the fermentation, where first organic acids are produced and then the acids are converted to alcohol will also contribute to the different profile. Nevertheless it has been assumed that the VOC and PM emission factors are the same for butanol from corn as they are for ethanol from corn.

Should real world information become available at a later date these factors can be updated.

6.4 HYDROGEN PLANTS

The emissions from hydrogen plants are not included in AP-42. As the hydrogen pathways have been added to GHGenius the emission factors have been reviewed. The following description of the emission factors in GHGenius 3.11 can be found in the model documentation.



In order to properly model the hydrogen fuel cycles it is necessary to estimate the emissions of criteria air contaminants from the reformer systems. In the GREET model these emissions are assumed to be the same as those from an industrial natural gas boiler. A similar approach was used by Spath and Mann. Contadini et al (2000) compared the emission factors for some of the contaminants from a number of studies. Contadini (1999) also published his own estimates based on modeling work done at the University of California at Davis. All of these emission factors are compared in the following table.

Table 6-4 Natural Gas Reformer Emission Factors

Emissions g/GJ Delucchi Spath Greet Contadini Fuel Evaporation 9.5 0.0 0.0 0.0 NMOC Exhaust 0.2 0.0 2.8 0.0 Methane 0.4 0.0 1.1 0.0 Carbon Monoxide 2.9 0.8 41.8 13.9 Nitrous Oxide 0.5 0.0 1.1 0.0 NOx 19.0 8.1 16.0 11.7 SOx 0.1 0.0 0.3 0.0 PM 0.1 0.2 3.8 0.0 Some of the differences in these emissions can be explained by different assumptions, Spath for example assumes that low NOx burners will be used in reformers. The LEM values tend to be mid range for most contaminants. Linde (1997) reported emission rates for a large natural gas steam reformer. These are shown in the following table. The methane and carbon monoxide emissions are much higher than Delucchi’s assumption.

Table 6-5 Linde SMR Emission Rates

Contaminant Emissions, g/GJ input Methane 14.25 Carbon Monoxide 19.95 NOx 20.90 SOx 0 Several other references were found for NOx and other contaminants for hydrogen production systems and for natural gas fired heaters. The NPRA filed comments to the US EPA on Best Available Control Technology (BACT) for petroleum refineries as part of the low sulphur gasoline rulemaking process. They reported that NOx emissions for uncontrolled NOx emissions were 43 to 56 grams per GJ and that the use of low NOx burners could reduce that to 19 to 29 grams/GJ. Some new refinery hydrogen systems have been designed with further NOx control strategies such as SCR or Urea injection but these are not likely to be employed on the small-scale systems.

Other emissions from hydrogen reformer systems were found in the US EPA BACT database and in the California BACT database. Particulate emissions for a naphtha reformer at a California refinery were 3.2 gm/GJ and carbon monoxide emissions ranged from 3.8 to 11.4 gm/GJ based on the fuel and the system.

The fuels being used for the hydrogen production systems do not all have the same combustion properties as natural gas so different emissions factors have been applied to the model. The emission factors used in the model are shown in the following table. The NOx emissions have been increase by 50% over natural gas emission rates for LPG, gasoline



and FT Distillate based on the EPA AP-42 guidelines for LPG combustion. These emissions are reduced by 50% for methanol based on the much lower temperatures required for methanol decomposition compared to natural gas reforming. The ethanol emission factors are assumed the same as natural gas. Sulphur emissions are higher for propane because of the sulphur content of the fuel and particulate emissions are assumed to be higher for the liquid hydrocarbon fuels due to their more complex molecular structures. An advanced user of the model could make changes to the model on Sheet N, rows 75 to 89.

Table 6-6 Emission Factors Assumptions

Emissions g/GJ Natural gas

Methanol Gasoline Ethanol FT Distillate

LPG Coal Wood

Evaporative VOCs 0.00 4.74 4.74 4.74 4.74 0.00 0.00 0.00 NMOC Exhaust 0.19 0.19 0.19 0.19 0.19 0.19 83.64 9.48 Methane 0.38 0.38 0.38 0.38 0.38 0.38 8.36 1.90 Carbon Monoxide 7.58 7.58 7.58 7.58 7.58 7.58 7.25 47.39 Nitrous Oxide 0.24 0.12 0.36 0.24 0.36 0.36 1.33 3.79 NOx 18.96 9.48 28.44 18.96 28.44 28.44 27.88 71.09 SOx 0.09 0.09 0.09 0.09 0.09 0.09 27.88 10.75 PM 2.84 2.84 2.84 2.84 2.84 2.84 5.58 23.70

No adjustments are made to these emission rates over time in the model although if the user had data available the capacity to change the emissions over time has been included in the model.

6.5 METHANOL PRODUCTION

There are no EPA AP-42 emission factors for methanol production. The methanol production process is similar to the production of hydrogen in that a syngas is first produced and then the syngas is reacted over a catalyst to produce methanol rather than purifying the gas to produce hydrogen. The emissions in GHGenius are calculated using the same fuel specific emission factors as were developed for hydrogen production.

The user can enter their own emission factors and rates of improvement factors on sheet N if that data is available. No changes have been made between versions 3.11 and 3.12.

6.6 SYNTHETIC GAS PRODUCTION

There is only one of these types of operations (coal fired) in commercial service and no specific process information is available from that operation. Other information on the process emissions for the wood or coal to SNG pathways was not identified. Since this process starts with the production of syngas it has been assumed that the emissions are similar to the hydrogen pathways using the same feedstock. In GHGenius the emissions are calculated based on the feedstock input to the process and not the fuel produced so while the emission rate for hydrogen and SNG pathways are the same based on the wood or coal input, they are different when compared on the basis of fuel produced because of the different process efficiencies.



6.7 FT DISTILLATE PLANTS

FT Distillate plants are also similar to hydrogen and methanol plants in that syngas is first produced and then the gas is reacted to produce a fuel, FT Distillate in this case.

The most recent look at FT Distillate processes in GHGenius was the work done to add the coal to FTD pathway to the model. As part of that work the estimated emissions from the reference reports (Bechtel and EES) are summarized in the following table along with the values that have been used on sheet N of GHGenius. The aldehydes and PM2.5 are not estimated in GHGenius for any of the FT Distillate pathways. These emission factors are generally lower than the coal to hydrogen values and may indicate that the coal to hydrogen values are conservative in the model.

Table 6-7 Coal to FTD Process Emissions Estimates

EES Bechtel Used for GHGenius

Grams/GJ Coal Grams/GJ Coal Grams/GJ CoalAldehydes (as HCHO) n.e.Fuel evaporation or leakage 9.46 NMOC process 5.64 6.04 Evaporation +NMOC process 15.50 Carbon in evap. + NMOC process 11.67 Ozone-weighted total NMOC 3.68 CH4 process 5.37 5.37CO 3.01 1.45 2.00 N20 0.20 0.20 NOx (NO2) 7.32 8.18 7.70 SOx (SO2) 14.20 18.15 16.00 PM 4.63 4.60 PM10 0.19 PM2.5 n.e. The emission factors for the other pathways have been set to be the same as the factors for hydrogen production for each fuel. Compared to the other FT pathways in GHGenius the emissions for the coal pathway are higher for NMOC, methane, SOx, and PM but lower for CO and NOx as summarized in the following table.



Table 6-8 Process Emissions Comparison

NG Coal Wood RDF Grams/GJ Grams/GJ Grams/GJ Grams/GJ Aldehydes (as HCHO) 0.00 0.00 0.47 0.47 Fuel evaporation or leakage 0.00 0.00 0.00 0.00 NMOC process 0.19 6.04 9.48 9.48 CH4 process 0.38 5.37 1.90 1.90 CO 7.58 2.00 47.39 47.39 N20 0.24 0.20 3.79 3.79 NOx (NO2) 18.96 7.70 71.09 71.09 SOx (SO2) 0.09 16.00 10.75 10.75 PM 2.84 4.60 23.70 23.70 PM10 0.09 0.19 23.70 23.70 PM2.5 0.00 0.00 23.70 23.70

The user can enter their own emission factors and rates of improvement factors on sheet N if that data is available. No rates of improvement have been entered but the structure is there in the model if the user has information available.

6.8 MIXED ALCOHOLS FACILITIES

Mixed alcohol processes have not been commercially developed so little information is available on the process emissions. There are several proposals to build small mixed alcohol plants that will focus on maximizing ethanol production. More information on the process emissions may become available once these plants start operation.

The default values that have been used in GHGenius are the same as those used for hydrogen production for the specific feedstock. This assumption is made based on the similarity of the processes and the desire for some consistency between pathways in the absence of better data.

6.9 BIODIESEL PLANTS

The process emission calculations for biodiesel production date back to the original LEM calculations and do not accurately reflect the current structure for biodiesel production in the model. The default values were suspect as well since they include a factor for NOx emissions, which are unlikely for process emissions. The process emissions should also be separated into emissions that represent the oil extraction process and the transesterification process because these pathways are separated in the model and can be separate facilities in actual operations.

This version of the model therefore calculates the process emissions for the two operations separately. On value is determined for the transesterification step that is applied to all biodiesel pathways and a second group of values is developed for each of the oil feedstocks. The basic structure of sheet N is the same for these new systems as it is for the rest of the process emission calculations. A base value is entered and the user can adjust how that changes over time. In all of the default cases it has been assumed that there are no changes over time. Note that the emissions resulting from the use of fuel in the process is calculated separately based on the fuel consumed and the rates of use.



6.9.1 Transesterification

Process related emissions from the conversion of fats and oils to biodiesel are relatively minor. Both the feedstock and the products have low volatility. The only volatile chemical that is used is methanol so some VOCs from the evaporation of methanol could be expected.

Methanol emissions will vary slightly depending on the process details employed. Based on some NEI data and the environmental assessment applications filed by some US biodiesel plants it is expected that methanol emissions could vary from 0.05 to 0.5 g/litre of biodiesel produced. The higher value will be used as the based value and it will be assumed that the emissions are eventually 80% controlled and that the 95% level of the minimum emissions is reached in 2005.

These emissions are added to all of the biodiesel production pathways on sheet Upstream Results.

6.9.2 Oil Extraction

The oil extraction process is generally more complex and emissions intensive that the trans esterification of the extracted oil. Seeds may be handled, conditioned, heated, expelled, washed with chemicals and purified. Furthermore there can be some significant differences in the emissions profile of the different seed extraction methods. To account for this the process emissions are now estimated separately for each of the oil feedstocks in the model.

6.9.2.1 Canola

According to AP-42 particulate matter emissions and VOC are the primary process emissions related to vegetable oil processing. Particulate matter emissions can total 1.35 kg/tonne of seed processed when all possible sources are considered and typical control strategies are employed. The model does not allocate these emissions between the oil and the meal automatically so we will allocate these emissions on a mass basis and so for canola oil this would represent 32 g/GJ of oil produced.

VOC emissions are related to hexane losses. Hexane is used to complete the extraction of the oil from the vegetable oilseeds. The EPA suggested that hexane loss may be 2.5 kg/tonne of seeds processed but not all of this will be emitted to the atmosphere as some will remain with the meal. We will assume that 50% of this is emitted to the atmosphere. After allocation this will total 30 grams/GJ of oil produced.

The emissions of the air contaminants per GJ of fuel delivered are summarized in the following table for canola biodiesel and petroleum diesel fuel.



Table 6-9 Comparison of Results GHGenius 3.11 and 3.12 Canola Biodiesel

GHGenius

3.11GHGenius

3.12GHGenius

3.11 GHGenius

3.12Fuel On Road Diesel Canola Biodiesel g /GJ Fuel Carbon dioxide (CO2) 15,689 15,719 5,088 4,936 Non methane organic compounds (NMOCs) 13 12 11 25 Methane (CH4) 134 125 58 55 Carbon monoxide (CO) 39 16 -12 -72 Nitrous oxide (N2O) 1 1 36 38 Nitrogen oxides (NO2) 54 72 300 237 Sulphur oxides (SOx) 30 74 28 42 Particulate matter (PM) 5 6 25 47 HFC-134a (mg) 0 0 3 3 CO2-equivalent GHG emissions 18,732 18,586 17,352 17,737

6.9.2.2 Soybeans

The emissions from processing soybeans are similar to those from canola processing and since we are allocating the emissions on a mass basis between the products the emissions for soybean oil extraction will be the same as they are for canola oil.

6.9.2.3 Palm

The extraction of the oil from the palm seed does not entail the use of hexane so VOC emissions from palm oil extraction should be close to zero. There will likely still be some particulate emissions from handling the fruit bunches and dealing with the husks.

Very little information is available on the emissions associated with palm oil extraction. A paper by Pleanjai et al reported PM emissions of 3.9 to 8.7 kg/tonne of oil produced but that included all sources included combustion sources. At the low end this would be 95 g/GJ of oil produced. We will attribute 65% of this to non-combustion emissions.

6.9.2.4 Tallow

The AP-42 guidance document for rendering operations does not contain any quantitative information. Some PM (from bone meal dryers) and VOC (from cooking vessels) emissions are known to be present. It will be assumed that the emissions are 30 g/GJ of each, a similar level to those of oilseed crushers.

6.9.2.5 Yellow Grease

Yellow grease production is often carried out at the same facilities as animal by-product rendering. The used cooking oil is processed to remove water and solids material. It will be assumed that the VOC emissions are similar to tallow production but that there are no PM emissions since no bone meal is produced.



6.9.2.6 Fish Oil

AP-42 reports an uncontrolled PM emission rate of 4 kg/tonne of fishmeal from fish oil extraction facilities. In addition odours are reported but not quantified. 85% of the production at these facilities is fishmeal and only 15% represents the oil fraction. Allocation the PM emissions by weight would mean that the PM emissions per tonne of oil are 3.4 kg/tonne or 80 g/GJ of oil.

Facilities in the developing world would likely have some controls applied to reduce PM emissions and address the odour concerns but most fish oil is produced in developing countries so no controls are applied in the default case.

The VOC emissions are assumed to be the same as tallow.

6.10 DIMETHYL ETHER PRODUCTION

Dimethyl Ether plants are just starting to be built for fuel production purposes. It has been assumed that the emission factors are the same as they are for methanol produced from natural gas due to the similarity of the processes.

The user can enter their own emission factors and rates of improvement factors on sheet N if that data is available. No rates of improvement have been entered but the structure is there in the model if the user has information available.



7. RESULTS A large number of small changes have been made to the emission factors in the model. These changes have also included further regionalization of some pathways and further differentiation of the Canadian emissions compared to the US emissions. While the focus of the work has been on the CAC emissions in a number of cases changes to methane and nitrous oxide emission factors have also been made. In addition there were some structural changes to how future emissions reductions are included in the model and the structure of how the biodiesel process emissions are calculated.

All of these changes have resulted in small changes in the projected GHG performance of the fuels included in the model. In the following table the upstream emissions for a selection of fuels is shown and compared to the results from version 3.11.

Table 7-1 Comparison of Upstream GHG Emissions GHGenius 3.11 vs. 3.12

GHGenius 3.11 GHGenius 3.12 g CO2 eq/GJ g CO2 eq/GJLow Sulphur Gasoline 22,607 22,426On Road Diesel 18,732 18,586Corn Ethanol 37,169 37,355Wheat Ethanol 38,055 38,330Canola Biodiesel 17,352 17,737Soy Biodiesel 23,817 24,222Tallow Biodiesel -6,508 -6,624SMR Hydrogen 108,793 108,899Electrolytic Hydrogen 127,807 127,950CNG 10,007 10,076LPG 12,373 12,207FT Natural Gas 31,449 31,300FT Coal 110,112 109,711Methanol (Natural Gas) 20,019 19,795



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